1. Field of the Invention
This invention relates to a method for recovering oil from a subterranean formation, and more particularly, to an improved flooding process for the recovery of crude oil.
2. Description of the Prior Art
The petroleum industry has recognized for many years that only a portion of the original oil in an oil reservoir can be produced by what is referred to as "primary recovery," i.e., where only initial formation energy is used to recover the crude oil. It is also well-known that conventional methods of supplementing primary recovery are relatively inefficient. Typically, a reservoir retains half its original oil even after the application of currently available "secondary" recovery techniques. Accordingly, there is a continuing need for improved recovery methods which will substantially increase the ultimate yield of petroleum from subterranean reservoirs.
"Waterflooding" is by far the most economical and widely practiced of secondary recovery methods. In such a process, water introduced through injection wells drives oil through the formation to offset producing wells. Much of the current work in secondary recovery technology has been directed toward improving the efficiency of waterflooding processes.
Surface-active agents, or surfactants, have been proposed for improving the efficiency of waterflooding processes. Much of the oil retained in the reservoir after a typical waterflood is in the form of discontinuous globules or discrete droplets trapped within the pore spaces. Because the normal interfacial tension between the reservoir oil and water is so high, these discrete droplets are unable to deform sufficiently to pass through narrow constrictions in the pore channels. When surface-active agents are added to the flooding water, they lower interfacial tension between the water and the reservoir oil and permit oil droplets to deform and flow with the flood water toward producing wells. It is generally accepted that the interfacial tension between the surfactant-containing phase and the reservoir oil must be reduced to less than 0.1 dyne/cm. for effective recovery.
In a waterflood oil-recovery process where the water contains a surfactant, the efficiency of the oil displacement is strongly affected by (1) the rate of surfactant loss, and (2) the surface activity (extent of lowering the oil/water interfacial tension) of the surfactant.
One difficulty in the use of surfactants in general and anionic surfactants in particular is their tendency to be depleted from the injection solution. The surfactants tend to be lost by precipitation as insoluble salts of materials, such as polyvalent metal ions, that may be dissolved in the fluid in the reservoir; by adsorption on the reservoir rocks; and/or by chemical conversion, such as hydrolysis of an active component of the surfactant system to a component that is insoluble, inactive, or detrimental in that system. If the surface-active agent is removed from the waterflood solution as it moves through the reservoir, the agent is not available to act at the oil/water interface. Quite naturally, surfactant depletion decreases oil recovery efficiency.
Another difficulty observed in the use of many anionic surfactants is the inability of the surfactant to exhibit high surface activity in high temperature reservoirs (i.e., temperatures of about 120.degree.F or more) and/or in high salinity environments (i.e., salinities of 2% NaCl or more). Generally, as the temperature of the reservoir and salinity of the brine solution in the reservoir increase, the surface activity of conventional anionic surfactants decreases. Surfactants have been suggested which exhibit some tolerance against either high temperatures or high salinity. None of these surfactants, however, have the ability to exhibit a high degree of surface activity under all types of reservoir conditions, including high salinity or high temperature, or both high temperature and high salinity reservoirs.
A number of approaches have been proposed to combat the problems of excessive surfactant depletion and poor surface activity in high-salinity environments. One approach is to inject a fluid into the reservoir before injecting the surfactant. For example, fresh water would be injected into the reservoir to lower the salinity of the brine in the formation and to reduce water hardness (calcium and magnesium). This approach, however, is not particularly desirable from a technical and economical standpoint. It is often very difficult and expensive to lower the salinity of the formation brine by this method. Another approach is to add a mixture of two (or more) surfactants to a surfactant solution. For example, it was suggested in U.S. Pat. No. 3,811,505, issued to Flournoy et al., that a nonionic surfactant such as polyethoxylated alkyl phenol or polyethoxylated aliphatic alcohol could be injected with an anionic surfactant for improved tolerance to water hardness. One problem with this approach is that the surfactants are sometimes incompatible with each other and/or the formation being flooded. A further problem or objection to the use of two different surfactants is the excessive cost. Still another problem is that chemically different agents will tend to undergo a chromatographic separation. When the surfactants are separated, the desired beneficial results are often lost. Still another approach is to add co-surfactants to anionic surfactants for improved brine tolerance. This approach, however, is not effective in all types of reservoirs.
It would be highly desirable to have a surfactant for water-flooding any oil-bearing reservoir, including reservoirs containing high-salinity brine, wherein the surfactant exhibits a high degree of surface activity with the oil and brine in the reservoir and a low depletion rate as the surfactant passes through the reservoir.